Multidirectional wellbore penetration system and methods of use

ABSTRACT

A drilling assembly includes a hydraulic jet disposed on a downhole end of a fluid line, and one or more adjustable jet nozzles on the hydraulic jet in multiple angular orientations relative to a central axis of the hydraulic jet. The one or more adjustable jet nozzles provide fluid pressure to penetrate a formation and cut multiple angular channels.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority, pursuant to 35 U.S.C. 517 119, to U.S.Provisional Patent Application Ser. No. 61/668,713, filed Jul. 6, 2012,the entirety of which is incorporated herein by reference.

FIELD OF THE DISCLOSURE

Embodiments disclosed herein relate generally to drilling wellbores.More particularly, embodiments disclosed herein relate to an apparatusand methods for multidirectional and multi-angle penetrations through aformation from any initial wellbore.

BACKGROUND

In drilling a borehole in the earth, such as for the recovery ofhydrocarbons or for other applications, it is conventional practice toconnect a drill bit on the lower end of an assembly of drill pipesections that are connected end-to-end so as to form a drillstring. Thedrill bit is rotated by rotating the drill string at the surface or byactuation of downhole motors or turbines, or by both methods. Withweight applied to the drill string, the rotating bit engages the earthenformation causing the bit to cut through the formation material byeither abrasion, fracturing, or shearing action, or through acombination of all cutting methods, thereby forming a borehole along apredetermined path toward a taret zone.

Traditionally, drilled oil and gas wells penetrate the formation with asingle wellbore, thereby catching the oil and gas from the connected anddrainable radius only. Horizontal wells may be single or multiple indirection, but in most cases are limited in multitude and high in cost.Likewise, radial drilling may also be single directed and is limited bypenetration and area coverage.

Accordingly, there exists a need for improved well productivity.

SUMMARY OF THE DISCLOSURE

In one aspect, embodiments disclosed herein relate to a drillingassembly including a hydraulic jet disposed on a downhole end of a fluidline and one or more adjustable jet nozzles on the hydraulic jet inmultiple angular orientations relative to a central axis of thehydraulic jet, wherein the one or more adjustable jet nozzles providefluid pressure to penetrate a formation and cut multiple angularchannels.

In other aspects, embodiments disclosed herein relate to a cuttingdevice including a cutter disposed on an end thereof; a spacer sectionproximate to the cutter; and a guide channel having a radius ofcurvature, wherein a length of the spacer section corresponds with theguide channel radius of curvature to create a particular cutter pathangle through a casing wall.

In other aspects, embodiments disclosed herein relate to a method ofdrilling a formation including inserting, into a formation channel, ahydraulic jet comprising one or more multi-directional jet nozzles,providing high pressure fluid through the multi-directional jet nozzles;and cutting one or more multi-angle lateral channels through theformation.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a cross-section view of field drainage laterals crossingvarious producing and non-producing reservoir layers.

FIG. 2 shows a side view of a hydraulically stabilized bottomholeassembly in accordance with one or more embodiments of the presentdisclosure.

FIG. 3 shows a cross-section view of an angled guide channel inaccordance with one or more embodiments of the present disclosure.

FIG. 4 shows a side view of a casing cutting device in accordance withone or more embodiments of the present disclosure.

FIG. 5 shows a side view of a casing cutting device for calculating anoptimized cutter length in accordance with one or more embodiments ofthe present disclosure.

DETAILED DESCRIPTION

The following is directed to various exemplary embodiments of thedisclosure. The embodiments disclosed should not be interpreted, orotherwise used, as limiting the scope of the disclosure, including theclaims. In addition, those having ordinary skill in the art willappreciate that the following description has broad application, and thediscussion of any embodiment is meant only to be exemplary of thatembodiment, and not intended to suggest that the scope of thedisclosure, including the claims, is limited to that embodiment.

In one aspect, embodiments disclosed herein relate to a hydraulicallystabilized bottomhole assembly having hydraulic jet nozzles and methodsfor production maximization of hydrocarbons, water, or gas-bearingformations. As shown in FIG. 1, a formation 5 is penetrated by highpressure fluid such that a multitude of channels 12 are formed from anoriginal wellbore 10. Original wellbore 10 may be a vertical, inclined,or horizontal wellbore. Channels 12 may extend from wellbore 10 in anydirection and at any angle. This network of channels 12 allows formaximum drainage of any interconnected fluid or gas bearing zones of theformation 5. The channels 12 may traverse multiple producing andnon-producing zones of the formation at an angle into the reservoir andmay connect all present fractures, layers, and cavities that are outsidethe reach of traditionally drilled vertical or angled wellbores.Additionally, the channels 12 may also be used as conduits for injectedchemicals, proppants, Steam, pressure, and/or fluids, which may add tothe productivity of the reservoir.

The bottomhole assembly 100 includes a hydraulic jet and a casing cutteras described below, where the hydraulic jet may be a static or dynamichydraulic jet. Referring to FIG. 2, a side view of a hydraulic jet 102in accordance with one or more embodiments of the present disclosure isshown. The hydraulic jet 102 includes a plurality of various angled andsized jet nozzles, including forward-facing jet nozzles 104 andrearward-facing jet nozzles 106. As used herein, “forward-facing” meansproviding fluid coverage of a forward facing 180 degree hemisphere.Likewise, as used herein, “rearward-facing” means providing fluidcoverage of a rearward facing 180 degree hemisphere (opposite that ofthe forward facing 180 degree hemisphere). The forward and rearward jetnozzles 104 and 106 are arranged at specific angles, depending uponformation characteristics generally. The forward and rearward jetnozzles 104 and 106 may be arranged in any direction to cover andprovide fluid pressure over an entire 360 degree circumference aroundthe hydraulic jet 102.

The jet nozzles 104 and 106 may include adjustable jet nozzles which aremanual or automated, and the jet nozzles may be adjusted at the surface(prior to inserting the jet into the wellbore), may be remotely adjusteddownhole, or both. Remote adjustment of the nozzle may be performed, forexample, by circulation of selected chemicals through the jet nozzles,where the selected chemicals dissolve, remove or otherwise eliminateminute sections or portions of the inner diameter of the jet nozzle,such as a ring of dissolvable material proximate the jet opening.

Jet nozzles disclosed herein may be static or dynamic, as noted above.As used herein, “dynamic” may refer to jet nozzles that move, skip froma fractional rotation to a full single rotation, vibrate, or rotateduring use. For example, “dynamic jet nozzles” may refer to jet nozzlesthat are vibrating, flip-flopping ½ or ¾ rotations, or rotating jets.Furthermore, as used herein, “static” may refer to jet nozzles that arefixed at a particular angle. Those skilled in the art will appreciatethat any combination of only dynamic jet nozzles, only static jetnozzles, and both dynamic and static jet nozzles may be used inaccordance with one or more embodiments of the present disclosure.

Jet sizing (i.e., diameter or taper) of the jet nozzles may bedetermined by the hydraulic fluid pressure desired for penetration intoa particular formation. The forward and rearward-facing jet nozzles 104and 106 may be similarly sized in certain embodiments, while in otherembodiments, the jet nozzles may vary in size. For example, sizing ofthe jet nozzles may take into account jetting pressure, which is adirect function of formation variables such as compressive strength,porosity, and consolidation. Such formation variables may increase ordecrease with formation depth and reservoir age. Formation penetrationis achieved by nozzle design that provides sufficient erosional forces(i.e., sufficient fluid volume rate) and sufficient impact forces (i.e.,sufficient fluid pressure) to create a lateral channel through thereservoir. Thus, for instance, jet nozzles in accordance with one ormore embodiments of the present disclosure may provide a fluid volumerate of between about 3 and 25 gallons per minute and a fluid pressureof between about 3,000 and 20,000 psi.

Still further, sizes of jet nozzles 104 and 106 may vary between about0.014 inches and about 0.1 inches or greater in certain embodiments.Additionally, the jet nozzles 104 and 106 may be positioned at anglesfrom less than about 5 degrees to about 45 degrees relative to a centralaxis of the hydraulic jet 102 to provide full hole penetration. Inharder formations, such jet angles may be closer to about 45 degreeswith smaller jet nozzle sizes, whereas in softer and unconsolidatedformations such parameters may have smaller angles and larger jet nozzlesizes. Further still, the jets may be either static or dynamic duringuse. For example, penetration may be enhanced by a static jet. However,dynamic jets, static, pulsing, or rotating, may be used for more denseand harder rock penetration, in addition to varying the jet nozzleangles and sizes.

The hydraulic jet 102 is connected by a high pressure flexible fluidline 108 to one or more hydraulic centralizers 110 disposed along alength of the flexible line 108. The hydraulic centralizers 110 includevarious sizes of jet nozzles 112 that form circumferential fluid streamsof limited length and impact radially outwards. The circumferentialfluid streams may be arranged such that a few inches of solid fluidstream is directed radially outward before the solid fluid streamdiffuses in a spray-like pattern to reduce the erosional effect of thecentralizer. For example, in certain embodiments, the solid fluid streammay be between about 1 inch and 5 inches. In other embodiments, thesolid fluid stream may be between about 1 inch and 3 inches.Furthermore, the jet nozzles 112 may be evenly spaced about acircumference of the hydraulic centralizers 110 in certain embodiments.In other embodiments, the jet nozzles 112 may be unequally spaced aboutthe circumference of the hydraulic centralizers 110, depending on suchcharacteristics, as formation hardness and erodability, fluid pressure,and other parameters.

The circumferential jet stream from the hydraulic centralizers 110centers the one or more circumferential jet arrangements such that aninherent stiffness of the flexible line 108 between the hydrauliccentralizers 110 is maintained. For example, a centralization effect maybe achieved by having a multitude of circumferential jet streamscentralizing the system. Rigidity may be obtained by placing the one ormore hydraulic centralizers 110 at locations along a length of theflexible line 108 in direct correlation with a stiffness coefficient ofthe flexible line 108 (which may be steel reinforced hose in certaininstances). The force that emits from the hydraulic centralizers 110 maybe a function of the jet nozzles 112 in the centralizer and hardness ofthe formation. Thus, the one or more hydraulic centralizers 110 act as acentralizing and stabilizing contact point against the wellbore wall.

The hydraulically stabilized bottomhole assembly and forward jet 100 mayallow for the use of and/or mixing of various types of jetting fluids,including, but not limited to, water, chemical combinations to stabilizea formation from hydration or assist the penetration by chemicalleaching or to clean out the formation of corrosion, asphalts,paraffins, and other clogging or production inhibiting compounds thatmay be present in the formation or are induced by exploration andproduction of the reservoir.

The bottomhole assembly 100 further includes a cutting tool 120 forcutting through a casing wall and exiting laterally from the mainvertical wellbore casing ahead of the hydraulic jet 102 of thebottomhole assembly 100. As shown in FIG. 3, the cutting tool includes atool guide body 140 that has an angled guide channel 142 through itscenter to at any desired inclination to deflect the cutting tool 120 ata particular angle into contact with the casing. The guide body 140 fitswithin a wellbore casing to be cut and is de-centered within thewellbore casing by one or more spring-loaded pads 144 to obtain flushwall contact at the exit point of channel 142. As used herein,“de-centered” refers to using the one or more spring-loaded pads 144urge the outer surface of the tool guide body 140 into flush contactwith an inner surface of the wellbore casing (not shown), such that theouter surface of the tool guide body 140 and the inner surface of thewellbore casing are substantially parallel and in flush contact. Theangled guide channel 142 dictates the angle at which the cutting tool120 drills into the formation, and in effect, the angle at which thehydraulic jet 102 of the bottomhole assembly 100 is ultimately insertedinto the formation. As such, the angled guide channel 142 may beconfigured having a radius of curvature 143, which cutter having anoptimized cutter length (as described in more detail below), provides anexit angle from the guide channel 142 at any angle as determined byformation characteristics and other variables. For example, the angledguide channel 142 may be configured to produce an angled channel in anyrange from about 5 degrees to close to 90 degrees relative to a centralaxis of the tool guide body 140.

Referring now to FIG. 4, cutting device 120 in accordance with one ormore embodiments of the present disclosure is shown. The cutting device120 is inserted through the guide channel 142 (shown in FIG. 3) of thetool guide body 140 to allow the cutting device 120 to bore through thecasing wall and into the surrounding formation at a desired angle. Thecutting device includes an upper adjustable non-rotating bearing sleeve122 and a lower adjustable non-rotating bearing sleeve 124 separated byan adjustable variable spacer section 128. The upper bearing sleeve 122is retained by a top bearing retainers 121 and 123. Likewise, the lowerbearing sleeve 124 is retained by a bottom bearing retainers 125 and126. The distance between the upper and lower adjustable non-rotatingbearings 122 and 124 may be varied. In addition, diameters of thenon-rotating bearings 122 and 124 may be varied.

The cutting device 120 may include a bull nose-type tungsten cutter 132or other similar cutters known to those skilled in the art connected tothe main body by a bit shaft of variable length and securing sleeve 130.In some embodiments, the cutter may be formed form a high speed steel orother metallurgically compatible materials. The securing sleeve 130 maybe secured by a set screw type locking mechanism (not shown) or similarlocking mechanism. With the adjustable diameters of the bearing sleeves122 and 124 and the adjustable length of the spacer 128 between thebearing sleeve 122 and 124 contact points, the bottomhole assembly 100can be adjusted to have an optimized cutter length (“AL”), such that thepath taken by the cutter 132 through the guide channel 142 provides thatthe cutter 132 cuts directly and only into the casing sidewall andavoids cutting into any part of the guide channel 142.

Referring now to FIG. 5, calculating an optimized cutter length (AL)between the non-rotating upper and lower bearings 122 and 124 includesinput of known tool parameters for a given tool. Therefore, given theseknown inputs, for any size tool, the cutter length (AL) may be optimizedsuch that the cutter 132 (FIG. 4) exiting the guide channel 142 cutsdirectly and only into the casing sidewall and avoids contacting anypart of the guide channel 142. For purposes of this application, theoptimized cutter length (AL) is measured from the axially opposed faces90 and 92 of the non-rotating bearings 122 and 124, respectively, asshown in FIG. 5. The known tool parameters include:

-   -   ID_(gst)=Inner diameter of guide channel    -   OD_(cut)=Cutter outer diameter    -   R_(c)=Radius of curvature of guide channel

A first radius (R₁) is calculated using the following equation:

R ₁ =R _(c) +ID _(gst)

A second radius (R₂) is calculated using the following equation:

R ₂ =R _(c) +OD _(cut)

Finally, an optimized cutter length (AL) is calculated using thefollowing equation:

AL=2*[√{square root over ((R ₂ ² −R ₁ ²))}]

In certain embodiments, the cutting device 120 and the hydraulic jet 102may be separate tools that are run and retrieved in separate runs intothe wellbore. For example, one or more cuts using a cutting device 120may be performed in a single run. Next, one or more formationpenetrating jet runs using a hydraulic jet 102 may be performed in asingle run.

In other embodiments, the cutting device 120 and hydraulic jet 102 maybe incorporated into a single tool which accomplishes both casingcutting and multi-directional hydraulic boring, where the casing cuttingand boring may be performed simultaneously or sequentially during one ormore trips into the wellbore.

The following description is illustrative of methods of using thehydraulically stabilized bottomhole assembly 100 described above inaccordance with one or more embodiments of the present disclosure. Thetool guide body 140 may first be inserted into the casing and set at adesired depth in the wellbore. The tool guide body 140 is locked in thecasing by expanding locking dogs 144 to position the tool eccentricallyflush to the casing wall at the point of exit and lock the tool. Thelocking dogs may be hydraulically, electrically, pneumatically, ormanually expanded, such as by, for example, a ball-drop mechanism.

The cutting device 120 is then inserted into the wellbore and the cutter132 is guided by the guide channel 142 within the tool guide body 140and into contact with the casing wall at a desired angle. The cutter 132is attached to a 360 degree flexible drive shaft that may be operatedhydraulically, pneumatically, or electrically to rotate the cutter andbore a hole through the casing wall and into the adjacent formation. Thehydraulic, pneumatic, or electric motor may be fed into the wellbore byuse of standard coil tubing, small drilling tubes, or rods. The cutter132 may continue to bore past the casing wall and into the formation toprovide a pilot bore in the formation past the casing wall into whichthe hydraulic jet and centralizers may be inserted.

The cutting device 120 is retrieved from the wellbore and the hydraulicjet 102 is inserted through the drilled hole in the casing and into theformation. The hydraulic jet 102 is centered within the bore in theformation by the circumferential jet stream from the hydrauliccentralizers 110. Forward facing jets 104 and rearward facing jets 106of the hydraulic jet 102 are arranged at predetermined angles to createmultiple angled laterals through the formation in multiple directions.The forward and rearward facing jets 104 and 106 are pressurized toprovide a high pressure fluid blast into the formation to form multipleangled laterals in the formation, as was shown in FIG. 1.

Advantageously, embodiments of the present disclosure provide abottomhole assembly that is capable of producing an extensive drainagepattern of multi-angle and multi-directional penetrations that allowsfor the connection of any and all fractures, fissures, cavities, andother porosity locations in the producing and adjacent non-penetratedreservoir sections to be connected and thereby draining the in-situfluids and gases to be extracted at a higher rate and improved recoveryrate. The bottomhole assembly has hydraulic power penetration andhydraulic stabilization power that allows for faster and deeperpenetration while controlling the angle and direction.

While the present disclosure has been described with respect to alimited number of embodiments, those skilled in the art, having benefitof this disclosure, will appreciate that other embodiments may bedevised which do not depart from the scope of the disclosure asdescribed herein. Accordingly, the scope of the disclosure should belimited only by the attached claims.

What is claimed is:
 1. A drilling assembly comprising: a hydraulic jetdisposed on a downhole end of a fluid line; and one or more adjustablejet nozzles on the hydraulic jet in multiple angular orientationsrelative to a central axis of the hydraulic jet, wherein the one or moreadjustable jet nozzles provide fluid pressure to penetrate a formationand cut multiple angular channels.
 2. The bottomhole assembly of claim1, further comprising one or more hydraulic centralizers disposed alonga length of the flexible line to centralize the hydraulic jet.
 3. Thebottomhole assembly of claim 2, wherein the one or more hydrauliccentralizers includes a plurality of circumferential radial jet nozzlesto provide a circumferential jet stream radially outward.
 4. Thebottomhole assembly of claim 3, wherein the radial jet nozzles areevenly spaced about a circumference of the hydraulic centralizers. 5.The bottomhole assembly of claim 3, wherein the radial jet nozzles areunevenly spaced about a circumference of the hydraulic centralizers. 6.The bottomhole assembly of claim 1, wherein the one or more jet nozzlesare configured having various diameters.
 7. The bottomhole assembly ofclaim 1, wherein a jet size of the one or more jet nozzles is adjustabledownhole.
 8. A cutting device comprising: a cutter disposed on an endthereof; a spacer section proximate to the cutter; and a guide channelhaving a radius of curvature, wherein a length of the spacer and bearingsection corresponds with the guide channel radius of curvature to createa particular cutter path angle through a casing wall.
 9. The bottomholeassembly of claim 8, wherein the guide channel has a radius of curvatureto provide an exit angle therefrom of between about 5 degrees and 90degrees relative to a central axis of the cutting device.
 10. The casingcutting device of claim 8, wherein the spacer section comprises at leasttwo bearing sleeves located axially on each end of the spacer section.11. The bottomhole assembly of claim 10, wherein the at least twobearing sleeves are non-rotating.
 12. The bottomhole assembly of claim8, wherein the guide channel is within a guide body de-centered within awellbore.
 13. The bottomhole assembly of claim 8, wherein the cuttercomprises a bull nose type high speed steel or tungsten cutter.
 14. Amethod of drilling a formation, the method comprising: inserting, into aformation channel, a hydraulic jet comprising one or moremulti-directional jet nozzles; providing high pressure fluid through themulti-directional jet nozzles; and cutting one or more multi-anglelateral channels through the formation.
 15. The method of claim 14,further comprising: traversing a cutter along a guide channel having aradius of curvature, providing a spacer section proximate to the cutter,wherein the spacer section has a length that corresponds with the radiusof curvature of the guide channel; and cutting one or more holes througha wellbore casing.
 16. The method of claim 15, further comprisingrunning the cutter and the hydraulic jet into the wellbore casing in asingle trip.
 17. The method of claim 15, further comprising de-centeringthe guide channel within the wellbore casing with a plurality ofspring-loaded locking pads.
 18. The method of claim 14, furthercomprising centralizing the hydraulic jet in the formation channel witha circumferential jet stream from one or more hydraulic centralizers.19. The method of claim 14, further comprising orienting the one or moremulti-directional jet nozzles in one or more angular directions.
 20. Themethod of claim 14, further comprising adjusting a size of the one ormore jet nozzles.